U.S. patent application number 12/847433 was filed with the patent office on 2012-02-02 for method for processing hydrocarbon pyrolysis effluent.
Invention is credited to James R. Arnold, Robert D. Strack.
Application Number | 20120024749 12/847433 |
Document ID | / |
Family ID | 44625980 |
Filed Date | 2012-02-02 |
United States Patent
Application |
20120024749 |
Kind Code |
A1 |
Strack; Robert D. ; et
al. |
February 2, 2012 |
Method For Processing Hydrocarbon Pyrolysis Effluent
Abstract
A method and system are disclosed for treating the effluent from
a hydrocarbon pyrolysis unit employing a small primary
fractionator. The method comprises cooling the effluent from a
furnace through a first heat exchanger, a vapor-liquid separator,
and a second heat exchanger before it is passed to a fractionator
for further processing. These heat exchangers may also be utilized
to heat a utility fluid as part of the cooling process. Further,
one or more generators and a third heat exchanger may also be used
to assist in heat recovery for the process.
Inventors: |
Strack; Robert D.; (Houston,
TX) ; Arnold; James R.; (Littleton, CO) |
Family ID: |
44625980 |
Appl. No.: |
12/847433 |
Filed: |
July 30, 2010 |
Current U.S.
Class: |
208/44 ; 196/46;
208/100; 208/103 |
Current CPC
Class: |
C10G 2400/20 20130101;
C10G 70/041 20130101; C10G 9/002 20130101 |
Class at
Publication: |
208/44 ; 208/100;
208/103; 196/46 |
International
Class: |
C10C 1/20 20060101
C10C001/20; C10G 15/00 20060101 C10G015/00; C10G 49/22 20060101
C10G049/22 |
Claims
1. A method for cracking a hydrocarbon feed, the method comprising:
providing a hydrocarbon feed to a hydrocarbon pyrolysis unit to
create cracked effluent; passing at least a portion of the cracked
effluent from the hydrocarbon pyrolysis unit through a first heat
exchanger; separating the at least a portion of the cracked
effluent from the first heat exchanger into a gaseous effluent and
a liquid effluent; passing at least a portion of the gaseous
effluent through a second heat exchanger; passing at least a
portion of the effluent from the second heat exchanger to a
fractionator; recovering heat from the at least a portion of the
effluent in the second heat exchanger by passing a utility fluid
through the second heat exchanger; and recovering heat from the at
least a portion of the cracked effluent in the first heat exchanger
by passing the utility fluid from the second heat exchanger through
the first heat exchanger.
2. The method of claim 1, comprising passing the utility fluid from
the first heat exchanger through the hydrocarbon pyrolysis unit to
heat the utility fluid.
3. The method of claim 1, comprising passing the at least a portion
of the effluent from the second heat exchanger to one or more steam
generators before passing the at least a portion of the effluent
from the second heat exchanger to the fractionator.
4. The method of claim 3, comprising passing the at least a portion
of the effluent from the one or more steam generators through a
third heat exchanger before passing the at least a portion of the
effluent from the one or more steam generators to the
fractionator.
5. The method of claim 4, comprising recovering heat from the at
least a portion of the effluent from the one or more steam
generators in the third heat exchanger by passing the utility fluid
through the third heat exchanger before passing the at least a
portion of the effluent from the one or more steam generators to
the fractionator.
6. The method of claim 3, comprising adjusting valves on the one or
more steam generators to control the heat recovery from the at
least a portion of the effluent passing through the one or more
steam generators.
7. The method of claim 1, wherein the utility fluid is heated in a
deaerator prior to passing through the first heat exchanger.
8. The method of claim 1, comprising driving a turbine with the
heated utility fluid from the first heat exchanger.
9. The method of claim 1, wherein the at least a portion of the
cracked effluent from the first heat exchanger is cooled in a
direct quench to at least a temperature at which tar, formed by
reaction among constituents of the effluent, condenses, prior to
the separating the gaseous effluent and the liquid effluent.
10. A hydrocarbon cracking system comprising: a hydrocarbon
pyrolysis unit configured to: receive a hydrocarbon feed; and
create a cracked effluent from the hydrocarbon feed; a first heat
exchanger in fluid communication with the hydrocarbon pyrolysis
unit and configured to: cool at least a portion of the cracked
effluent from the hydrocarbon pyrolysis unit; and heat at least a
portion of a utility fluid; and a separator in fluid communication
with the first heat exchanger and configured to separate the at
least a portion of the cracked effluent into liquid effluent and
gaseous effluent; a second heat exchanger in fluid communication
with the separator and configured to: cool at least a portion of
the effluent from the separator; heat the utility fluid prior to
the first heat exchanger receiving the at least a portion of the
utility fluid; and a fractionator in fluid communication with the
second heat exchanger and configured to receive the at least a
portion of the effluent from the second heat exchanger.
11. The system of claim 10, wherein the hydrocarbon pyrolysis unit
is configured to heat the at least a portion of a utility fluid
from the first heat exchanger, wherein the at least a portion of a
utility fluid and the at least a portion of the cracked effluent
are maintained in separate non-commingling streams in the
hydrocarbon pyrolysis unit.
12. The system of claim 10, comprising one or more steam generators
in fluid communication between the second heat exchanger and the
fractionator and configured to pass the at least a portion of the
effluent from the second heat exchanger to the fractionator.
13. The system of claim 12, comprising a third heat exchanger in
fluid communication between the one or more steam generators and
the fractionator and configured to cool the at least a portion of
the effluent before passing the at least a portion of the effluent
to the fractionator.
14. The system of claim 13, wherein the third heat exchanger is in
fluid communication with the second heat exchanger and configured
to recover heat from the at least a portion of the effluent by
passing the utility fluid through the third heat exchanger prior to
the second heat exchanger receiving the utility fluid; and wherein
the utility fluid and the at least a portion of the effluent are
maintained in separate non-commingling streams in the second heat
exchanger.
15. The system of claim 14, comprising a bypass valve coupled
between a source of the utility fluid, the first heat exchanger and
the third heat exchanger and configured to: in a first position,
restrict a first portion of the utility fluid from passing to the
third heat exchanger from the source and direct a first remaining
portion of the utility fluid to the first heat exchanger via a
bypass line; and in a second position, direct a second portion of
the utility fluid to pass to the third heat exchanger from the
source and restrict a second remaining portion of the utility fluid
from passing through the bypass line to the first heat
exchanger.
16. The system of claim 12, comprising a control valve coupled to
at least one of the one or more steam generators and configured to
control the cooling of the at least a portion of the effluent
passing through the one or more steam generators.
17. The system of claim 10, comprising a deaerator in fluid
communication with the second heat exchanger and configured to
preheat the utility fluid prior to passing the utility fluid to the
second heat exchanger.
18. The system of claim 10, wherein the first heat exchanger is
configured to cool the at least a portion of the cracked effluent
from the hydrocarbon pyrolysis unit and provide the at least a
portion of the cracked effluent to a direct quench that cools the
at least a portion of the cracked effluent to a temperature at
which tar, formed by reaction among constituents of the at least a
portion of the cracked effluent, condenses.
19. The system of claim 10, comprising a drive turbine configured
to receive the at least a portion of the heated utility fluid from
the hydrocarbon pyrolysis unit.
20. The system of claim 10, wherein the utility fluid and the at
least a portion of the effluent are maintained in separate
non-commingling streams.
21. A method for steam cracking a hydrocarbon feed, the method
comprising: providing a hydrocarbon feed to a hydrocarbon pyrolysis
unit to create a cracked effluent; separating at least a portion of
the cracked effluent from the hydrocarbon pyrolysis unit, wherein
gaseous effluent is separated from liquid effluent including steam
cracked tar; cooling at least a portion of the gaseous effluent in
a first heat exchanger; passing at least a portion of the effluent
from the first heat exchanger to one or more steam generators;
cooling the at least a portion of the effluent from the one or more
steam generators in a second heat exchanger; and passing the at
least a portion of the effluent from the second heat exchanger to a
fractionator.
22. The method of claim 21, comprising passing the at least a
portion of the cracked effluent from the hydrocarbon pyrolysis unit
through a third heat exchanger before passing the at least a
portion of the cracked effluent to the separator.
23. The method of claim 22, comprising heating a utility fluid by
passing the utility fluid through the hydrocarbon pyrolysis unit
and using the heated utility fluid in an additional process.
24. The method of claim 23, recovering heat from the at least a
portion of the effluent in the first heat exchanger by passing the
utility fluid by through the first heat exchanger prior to passing
the utility fluid through hydrocarbon pyrolysis unit.
25. The method of claim 24, comprising recovering heat from the at
least a portion of the effluent in the second heat exchanger by
passing the utility fluid through the second heat exchanger prior
to passing the utility fluid through the first heat exchanger.
26. The method of claim 25, comprising adjusting valves on the one
or more steam generators to control the heat recovery from the at
least a portion of the effluent passing through the one or more
steam generators.
27. The method of claim 24, wherein the utility fluid is heated in
a deaerator prior to passing through the first heat exchanger.
28. The method of claim 22, wherein the at least a portion of the
cracked effluent is cooled in the third heat exchanger to at least
a temperature above the temperature at which tar, formed by
reaction among constituents of the effluent, condenses.
29. The method of claim 23, wherein using the heated utility fluid
in the additional process comprises driving a turbine with the
heated utility fluid.
30. A gaseous effluent handling system comprising: a hydrocarbon
pyrolysis unit configured to: receive a hydrocarbon feed; and
create a cracked effluent from the hydrocarbon feed; and a
separator in fluid communication with the hydrocarbon pyrolysis
unit and configured to separate liquid effluent having steam
cracked tar and gaseous effluent from at least a portion of the
cracked effluent from the hydrocarbon pyrolysis unit; and a first
heat exchanger in fluid communication with the separator and
configured to cool at least a portion of the gaseous effluent from
the separator; one or more steam generators in fluid communication
with the first heat exchanger and configured to receive the at
least a portion of the effluent from the first heat exchanger; a
second heat exchanger in fluid communication with the one or more
generators and configured to cool the at least a portion of the
effluent from the one or more steam generators; and a fractionator
in fluid communication with the second heat exchanger and
configured to receive the at least a portion of the effluent from
the second heat exchanger.
31. The system of claim 30, comprising a third heat exchanger in
fluid communication between the separator and the hydrocarbon
pyrolysis unit and configured to cool the at least a portion of the
cracked effluent passing through the third heat exchanger to the
separator.
32. The system of claim 30, wherein the hydrocarbon pyrolysis unit
is configured to heat a utility fluid by passing the utility fluid
through the hydrocarbon pyrolysis unit.
33. The system of claim 32, wherein the first heat exchanger is
configured to recover heat from the at least a portion of the
effluent in the first heat exchanger by passing the utility fluid
by through the first heat exchanger prior to passing the utility
fluid through hydrocarbon pyrolysis unit.
34. The system of claim 33, wherein the second heat exchanger is
configured to recover heat by passing the utility fluid through the
second heat exchanger prior to passing the utility fluid through
the first heat exchanger.
35. The system of claim 34, comprising one or more valves coupled
to the one or more steam generators and configured to adjust the
heat recovery from the at least a portion of the effluent passing
through the one or more steam generators.
Description
FIELD OF THE INVENTION
[0001] The present invention is directed to a method for processing
the effluent from hydrocarbon pyrolysis units, especially those
units utilizing liquid feeds.
BACKGROUND OF THE INVENTION
[0002] The production of light olefins (ethylene, propylene and
butenes) from various hydrocarbon feedstocks typically utilizes the
technique of pyrolysis or steam cracking. Pyrolysis involves
heating the feedstock sufficiently to cause thermal decomposition
of the larger molecules. Then, the effluent from the cracking
furnace may be cooled by using conventional processes or
equipment.
[0003] This pyrolysis process, however, may produce molecules which
tend to combine to form high molecular weight materials known as
tars. Tars are high-boiling point, viscous, reactive materials that
can foul equipment under certain conditions. The fouling of the
equipment should be minimized to avoid inefficiencies and downtime
associated with cleaning of the equipment. The formation of tars,
after the pyrolysis effluent leaves the steam cracking furnace can
be minimized by rapidly reducing the temperature of the effluent
exiting the pyrolysis unit to a level at which the tar-forming
reactions are greatly slowed.
[0004] Various techniques may be used to cool pyrolysis unit
effluent and remove the resulting heavy oils and tars. For
instance, one approach may employ heat exchangers followed by a
water quench tower in which the condensables are removed. This
technique has proven effective when cracking light gases, primarily
ethane, propane and butane, because crackers that process light
feeds, collectively referred to as gas crackers, produce relatively
small quantities of tar. For heavier feedstocks, which may be used
with steam crackers that crack naphthas (e.g., liquid cracking),
another approach may involve heat exchangers that remove some of
the heat from liquid cracking, but only down to the temperature at
which tar begins to condense. Below this temperature, conventional
heat exchangers should not be used because they foul rapidly from
accumulation and thermal degradation of tar on the heat exchanger
surfaces. As such, in a commercial liquid cracker configuration,
the cooling of the effluent from the cracking furnace is normally
achieved using a system of transfer line heat exchangers, usually a
direct quench, a primary fractionator, and a water quench tower or
indirect condenser.
[0005] As may be appreciated, effective heat recovery enhances the
operation of the system. That is, effective heat recovery from the
effluent of steam cracking furnaces is advantageous in the overall
energy efficiency of an olefins plant. For example, the outlet
temperature of a steam cracking furnace typically operates at about
1,500.degree. F. (815.degree. C.) (with the temperature depending
on the quality of the feedstock and cracking severity). By
operating at this high temperature, a large quantity of heat may be
recovered as the effluent is cooled to near ambient temperature for
initial product separation and compression.
[0006] In typical hydrocarbon cracking systems, a transfer line
exchanger (TLE) is used to generate super-high pressure (SHP) steam
from the initial cooling of furnace effluent as it exits the
cracking furnace. The SHP steam may include pressures ranging from
about 1,500 pounds per square inch gauge (psig) to about 2,000 psig
(about 10,450 kilopascal (kpa) to about 13,982 kpa). The first heat
exchanger raises saturated SHP steam from high pressure boiler feed
water. The saturated SHP steam generated by the TLE may further be
superheated in the convection section of the furnace to increase
the amount of work that it can produce.
[0007] However, the TLE in typical configurations can only recover
a portion of furnace effluent heat, as it is limited by the
temperature at which tar begins to condense (i.e., tar dew point).
That is, the outlet temperature on the process side of the TLE is
limited by fouling when the dew point is encountered. As noted
above, heavy components in the effluent condense at the tar dew
point and foul the TLE surfaces, rendering them ineffective for
heat transfer. For naphtha crackers, tar dew point fouling limits
TLE outlet temperatures to a minimum of about 700.degree. F.
(371.degree. C.). For feeds heavier than naphtha, TLE outlet
temperatures are higher than 700.degree. F. (371.degree. C.)
because the effluent tar dew points are higher. The TLE outlet
temperature is also limited by the temperature of steam generation
temperature, which is about 600.degree. F. (315.degree. C.) for a
1500 psig (10,450 kpa) steam. As such, a TLE adjacent to the
furnace can only recover effluent heat from liquid cracking down to
a temperature between about 650.degree. F. to about 1000.degree. F.
(about 343.degree. C. to about 538.degree. C.) depending on the
heaviness of the feed.
[0008] After initial cooling, the effluent is typically provided to
the primary fractionator system. The primary fractionator system is
a very complex set of equipment that typically includes an oil
quench section, a primary fractionator tower and one or more
external oil pumparound loops. At the oil quench section, quench
oil is added to cool the effluent stream from about 400.degree. F.
to about 650.degree. F. (about 204.degree. C. to about 343.degree.
C.), thereby condensing tar present in the stream. In the primary
fractionator tower, the condensed tar is separated from the
remainder of the stream, heat is removed in one or more pumparound
zones by circulating oil and a pyrolysis gasoline fraction is
separated from heavier material in one or more distillation zones.
In the one or more external pumparound loops, oil, which is
withdrawn from the primary fractionator, is cooled using indirect
heat exchangers and then returned to the primary fractionator or
the direct quench point.
[0009] The primary fractionator system with its associated
pumparounds is the one of the more expensive components in the
entire cracking process. The primary fractionator tower itself is
the largest single piece of equipment in the process, typically
being about twenty-five feet in diameter and over a hundred feet
high for a medium size liquid cracker. The tower is large because
it is in effect fractionating two minor components, tar and
pyrolysis gasoline, in the presence of a large volume of low
pressure gas and needing to reject significant excess heat in the
feed. The pumparound loops are likewise large, handling over 3
million pounds per hour (lb/hr) (1,363,636 kg/hr) of circulating
oil in the case of a medium size cracker. Heat exchangers in the
pumparound circuit are necessarily large because of high flow
rates, close temperature approaches needed to recover the heat at
useful levels, and allowances for fouling.
[0010] In addition, the primary fractionator has a number of other
limitations and problems. In particular, heat transfer takes place
twice, i.e., from the gas to the pumparound liquid inside the tower
and then from the pumparound liquid to the external cooling
service. This effectively requires investment in two heat exchange
systems, and imposes two temperature approaches (or differentials)
on the removal of heat, thereby reducing thermal efficiency.
[0011] Moreover, despite the fractionation that takes place between
the tar and gasoline streams, both streams often need to be
processed further. Sometimes the tar needs to be stripped to remove
light components, whereas the gasoline may need to be
refractionated to meet its end point specification.
[0012] Further, the primary fractionator tower and its pumparounds
are prone to fouling. Coke accumulates in the bottom section of the
tower and has to eventually be removed during plant turnarounds.
The pumparound loops are also subject to fouling, requiring removal
of coke from filters and periodic cleaning of fouled heat
exchangers. Trays and packing in the tower are sometimes subject to
fouling, potentially limiting plant production. The system also
contains a significant inventory of flammable liquid hydrocarbons,
which is not desirable from an inherent safety standpoint.
[0013] There is therefore a need for an enhanced method for cooling
pyrolysis unit effluent and providing effective heat recovery for
the same. Further, there is therefore a need for a simplified
method for cooling pyrolysis unit effluent and removing the
resulting heavy oils and tars which obviates the need for a primary
fractionator tower and its ancillary equipment. The present
techniques provide effective heat recovery methods and/or effluent
cooling methods that overcome one or more of the deficiencies
discussed above.
[0014] Related material may be found in the following: U.S. Pat.
Nos. 3,907,661; 3,923,921; 3,959,420; 4,121,908; 4,150,716;
4,233,137; 4,279,733; 4,279,734; 4,444,697; 4,446,003; 5,092,981;
5,107,921; 5,294,347; and 5,324,486. Additional material may be
found in Intl. Patent App. Nos. 2000/56841 and 1993/12200; Great
Britain Patent Nos. 1,390,382 and 1,309,309; EP Patent No. 205 205
and Japanese Patent No. 2001-40366. Further still, additional
material may be found in the following publication: Lohr et al.,
"Steam-cracker Economy Keyed to Quenching," Oil & Gas Journal,
Vol. 76 (No. 20), pp. 63-68, (1978).
SUMMARY OF THE INVENTION
[0015] In one embodiment, a method for cracking a hydrocarbon feed
is described. The method comprises providing a hydrocarbon feed to
a hydrocarbon pyrolysis unit to create cracked effluent; passing at
least a portion of the cracked effluent from the hydrocarbon
pyrolysis unit through a first heat exchanger; separating the at
least a portion of the cracked effluent from the first heat
exchanger into a gaseous effluent and a liquid effluent, which may
be in a vapor-liquid separator; passing at least a portion of the
gaseous effluent from a separator through a second heat exchanger;
passing the at least a portion of the effluent from the second heat
exchanger to a fractionator; recovering heat from the at least a
portion of the gaseous effluent in the second heat exchanger by
passing a utility fluid through the second heat exchanger; and
recovering heat from the at least a portion of the cracked effluent
in the first heat exchanger by passing the utility fluid from the
second heat exchanger through the first heat exchanger. The process
may further include using the heated utility fluid in an additional
process, such as operating a turbine.
[0016] In another embodiment, a hydrocarbon cracking system is
described. This system comprises a hydrocarbon pyrolysis unit, a
separator, a first heat exchanger, a second heat exchanger and a
fractionator. The hydrocarbon pyrolysis unit is configured to
receive a hydrocarbon feed; and create a cracked effluent from the
hydrocarbon feed. Further, the first heat exchanger is in fluid
communication with the hydrocarbon pyrolysis unit and configured to
cool at least a portion of the cracked effluent from the
hydrocarbon pyrolysis unit; and heat at least a portion of a
utility fluid. The separator is in fluid communication with the
first heat exchanger and configured to separate liquid effluent and
gaseous effluent from the at least a portion of the cracked
effluent. The second heat exchanger in fluid communication with the
separator and configured to cool at least a portion of the gaseous
effluent from the separator; heat the at least a portion of the
utility fluid prior to the first heat exchanger receiving the at
least a portion of the utility fluid. The fractionator may be in
fluid communication with the second heat exchanger and configured
to receive the at least a portion of the effluent from the second
heat exchanger.
[0017] In yet another embodiment, a method for steam cracking a
hydrocarbon feed is described. The method comprising providing a
hydrocarbon feed to a hydrocarbon pyrolysis unit to create cracked
effluent; separating at least a portion of the cracked effluent
from the hydrocarbon pyrolysis unit, wherein gaseous effluent is
separated from liquid effluent, which may include steam cracked tar
along with other bottoms; cooling at least a portion of the gaseous
effluent from the separator in a first heat exchanger; passing at
least a portion of the effluent from the first heat exchanger to
one or more steam generators; passing at least a portion of the
effluent from the one or more steam generators to a second heat
exchanger; and passing the at least a portion of the effluent from
the second heat exchanger to a fractionator.
[0018] In yet still another embodiment, an effluent handling system
is described. This system comprises a hydrocarbon pyrolysis unit, a
separator, a first heat exchanger, a second heat exchanger, one or
more steam generators, and a fractionator. The hydrocarbon
pyrolysis unit is configured to receive a hydrocarbon feed; and
create a cracked effluent from the hydrocarbon feed. The separator
is in fluid communication with the hydrocarbon pyrolysis unit and
configured to separate liquid effluent, such as steam cracked tar
along with other bottom products, and gaseous effluent from at
least a portion of the cracked effluent from the hydrocarbon
pyrolysis unit. The first heat exchanger is in fluid communication
with the separator and configured to cool at least a portion of the
gaseous effluent from the separator. The one or more steam
generators are in fluid communication with the first heat exchanger
and configured to receive the at least a portion of the effluent
from the first heat exchanger. The second heat exchanger in fluid
communication with the one or more generators and configured to
cool the at least a portion of the effluent from the one or more
steam generators. The fractionator in fluid communication with the
second heat exchanger and configured to receive the at least a
portion of the effluent from the second heat exchanger.
BRIEF DESCRIPTION OF THE DRAWING
[0019] FIG. 1 is a block flow diagram for recovering heat from the
cooling of effluent from a cracked hydrocarbon feed according to an
exemplary embodiment of the present techniques.
[0020] FIG. 2 is a block flow diagram for recovering heat from the
cooling of effluent from a cracked hydrocarbon feed according to an
alternative exemplary embodiment of the present techniques.
[0021] FIG. 3 is a schematic flow diagram for recovering heat from
the cooling of cracked hydrocarbon effluent according to another
alternative exemplary embodiment of the present techniques.
[0022] FIG. 4 is another schematic flow diagram for recovering heat
from the cooling of cracked hydrocarbon effluent according to yet
another alternative exemplary embodiment of the present
techniques.
[0023] The invention will be described in connection with its
preferred embodiments of the present techniques. However, to the
extent that the following detailed description is specific to a
particular embodiment or a particular use of the invention, this is
intended to be illustrative only, and is not to be construed as
limiting the scope of the invention. On the contrary, it is
intended to cover all alternatives, modifications and equivalents
that may be included within the spirit and scope of the invention,
as defined by the appended claims.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0024] The present techniques provide an efficient arrangement to
treat the effluent stream from a hydrocarbon pyrolysis unit, which
may be referred to as a pyrolysis reactor or furnace, so as to
remove and recover heat therefrom and to separate desired
hydrocarbons. For instance, the present techniques may separate
C.sub.5+ hydrocarbons, providing separate pyrolysis gasoline, gas
oil, quench oil, and tar fractions, as well as the desired
C.sub.2-C.sub.4 olefins in the effluent without utilizing primary
fractionator pumparounds.
[0025] Typically, the effluent used in the one or more embodiments
of the present techniques is produced by pyrolysis of a hydrocarbon
feed boiling in a temperature range from about 40.degree. C. to
about 704.degree. C. (about 104.degree. F. to about 1300.degree.
F.), such as naphtha, tailed crudes or gas oil. For example, the
effluent may be produced by pyrolysis of a hydrocarbon feed having
a final boiling point above about 180.degree. C. (about 356.degree.
F.), such as a feed heavier than naphtha. Such feeds include those
boiling in the range from about 177.degree. C. to about 538.degree.
C. (about 350.degree. F. to about 1000.degree. F.), from about
204.degree. C. to about 510.degree. C. (about 400.degree. F. to
about 950.degree. F.). Typical heavier than naphtha feeds can
include heavy condensates, gas oils, hydrocrackates, kerosene,
condensates, tailed crude oils, and/or tailed crude oil fractions,
e.g., tailed reduced crude oils. The temperature of the effluent at
the outlet from the pyrolysis reactor is normally in the range of
from about 760.degree. C. to about 930.degree. C. (about
1400.degree. F. to about 1706.degree. F.) and the present
techniques provides a method of cooling the effluent to a desired
temperature at a fractionator, which may include temperatures in
the range of about 100.degree. C. to about 200.degree. C.
(212.degree. F. to 392.degree. F.). At this temperature range, the
desired C.sub.2-C.sub.4 olefins can be further cooled and
compressed efficiently.
[0026] To effectively manage the heat removal and recovery, one or
more embodiments of the present techniques involve an optimized
arrangement or configuration of heat exchangers for removing and
recovering heat from the effluent of a cracker. Typically, a single
heat exchanger is limited by the temperature differential between
temperature of the hot effluent stream and the temperature of the
utility fluid stream. The use of two or more cooling stages,
specifically in a specific sequence, overcomes this limitation by
providing more countercurrent flow arrangement of hot and cold
streams. As such, it is beneficial to configure the heat exchangers
to provide two or more stages of heating for a utility fluid, such
as boiler feed water, while also providing a two or more stages of
cooling for the effluent from the furnace. The initial or first
stage may involve higher temperatures, while the later or second
stage involves lower temperatures. As a result, the two stages of
heating and cooling (e.g., two or more heat exchangers in this
configuration or sequence) are able to heat the utility fluid to a
higher temperature than is possible with any single heat exchanger,
and provide an efficient mechanism for recovering heat from the
effluent.
[0027] Further, in other embodiments, these heat exchangers may be
utilized with other equipment in specific configurations to further
enhance the heat recovery process of the hydrocarbon cracking
system. These configurations or arrangements may be utilized to
provide a larger temperature differential for the heat exchangers
in the different heating and cooling stages, as will be discussed
further below. For example, the heat exchangers may be arranged
with one or more steam generators in certain embodiments to recover
heat in a more efficient manner.
[0028] Moreover, in the various embodiments discussed further
below, it should be appreciated that the utility fluid and the
effluent from the furnace are separate streams that do not
commingle. Each of these different streams may be maintained at
different pressures based on the specific configuration and
operation designs for the system. As an example, the heat
exchangers may include transfer line exchangers, tube-in-tube
exchangers or shell and tube exchangers.
[0029] Turning to FIG. 1, a block flow diagram 100 of a process for
recovering heat from the cooling of cracked hydrocarbon effluent
according to an exemplary embodiment of the present techniques is
disclosed. In this flow diagram 100, a hydrocarbon pyrolysis unit
102 (e.g., a cracker, reactor or furnace) is provided along with a
first heat exchanger 104, a separator 106, a second heat exchanger
108, and a fractionator 110. These units 102-110, which are part of
a hydrocarbon cracking system, are used together in a specific
arrangement to recovery heat from the cracked hydrocarbon effluent
as it is cooled. This process involves cracking a hydrocarbon feed
and the cracked hydrocarbon effluent being cooled in various
stages, while a utility fluid is heated to recover energy input
into the hydrocarbon cracking process. In particular, the cooling
of the cracked hydrocarbon effluent is described in blocks 122-130,
while the heating of the utility fluid is described in blocks
134-138.
[0030] To begin, a hydrocarbon feed is provided at block 120. The
hydrocarbon feed may include ethane, propane, butane, oils,
naphtha, pentane, gas oil, condensate and crude, for example. At
block 122, the hydrocarbon feed is cracked to produce an effluent.
This cracking process may include gas cracking, steam cracking, or
liquid cracking, as may be appreciated by those skilled in the art.
As specific examples, U.S. Patent App. Nos. 2007/0007172 and
2007/0007174, which are hereby incorporated by reference, describe
exemplary cracking processes. As noted above, the cracking of the
hydrocarbon feed, which produces an effluent, may include
temperatures from about 760.degree. C. to about 930.degree. C.
(about 1400.degree. F. to about 1706.degree. F.) (with the
temperature depending on the quality of the hydrocarbon feed). As
part of the cracking process, the hydrocarbon feed is heated to
cause thermal decomposition of the feed to produce lower molecular
weight hydrocarbons, such as C.sub.2-C.sub.4 olefins.
[0031] To cool the effluent, various steps are performed with the
hydrocarbon cracked effluent, as shown in blocks 124-130. In block
124, the effluent is cooled in a first heat exchanger 104. The heat
of the effluent may be transferred to the utility fluid through the
first heat exchanger 104, which may be a transfer line exchanger
(TLE), for example. In this stage, the effluent may be cooled from
a temperature at the inlet of the first heat exchanger 104, which
may be the same or below the temperature of the furnace outlet to a
first heat exchanger outlet temperature. As may be appreciated, the
temperature range in the first stage may vary depending on the
different hydrocarbon feeds. Again, as noted above, the first heat
exchanger outlet temperature should be configured to prevent
fouling, e.g., being above the tar dew point fouling limits
371.degree. C. to 537.degree. C. (700.degree. F. to 1000.degree.
F.).
[0032] The first heat exchanger may optionally be coupled to a
direct quench. The direct quench may cool the effluent from the
first heat exchanger 104 to at least a temperature at which tar,
formed by reaction among constituents of the effluent, condenses.
The direct quench may include an oil quench, a water quench or
other suitable process. As an example, U.S. Pat. No. 3,923,921
describes a direct quench process.
[0033] Once the tar is condensed, the effluent may be separated
into different streams, such as a liquid effluent and a gaseous
effluent, as shown in block 126. The liquid effluent may include
steam cracked tar along with other bottoms. The steam cracked tar,
which may be pyrolysis fuel oil, is typically obtained as a bottoms
product, which nominally has a boiling point of 550.degree. F.+
(288.degree. C.+) and higher (e.g., temperatures above 550.degree.
F. or above 288.degree. C.). The separator 106 may include a
vapor-liquid separator or tar knock-out drum, as is known in the
art. The separator 106 may operate at a temperature that is same as
or less than the first heat exchanger outlet temperature to a
separator outlet temperature. The operating temperature for the
separator 106 may be adjusted depending on the severity of
operation of the first heat exchanger 104, hydrocarbons feed, or
other factors. Accordingly, it should be appreciated that after the
effluent passes from the first heat exchanger 104 and before it
enters the separator 106, it may be further cooled by direct
injection of a small amount of fluid or in a direct quenching
process.
[0034] At block 128, the gaseous effluent from the separator 106
may be further cooled. Similar to the discussion above regarding
the first heat exchanger, the heat of the gaseous effluent may be
transferred to the utility fluid through a second heat exchanger
108, which may be a shell and tube heat exchanger, for example. In
this stage, the gaseous effluent may be cooled from a temperature
that is the same as or less than the separator outlet temperature
to a second heat exchanger outlet temperature. The second heat
exchanger outlet temperature may be adjusted based on the desired
temperature differential for this unit.
[0035] At block 130, the effluent from the second heat exchanger
108 may be provided to another unit for further processing of the
effluent. As an example, the unit may be a fractionator 110, or
more particularly, a mini-fractionator. The fractionator 110 may be
a mini-primary fractionator, which is further described in U.S.
Patent App. No. 2007007174.
[0036] As part of the heat recovery process, a utility fluid is
heated in various stages by at least a portion of the hydrocarbon
cracked effluent, as described in blocks 134-138. In block 132, a
utility fluid is provided to the hydrocarbon cracking system. The
utility fluid may include boiler feed water from a source, such as
a deaerator, or may include any other suitable fluid. Then, the
utility fluid is heated in block 134. In particular, the utility
fluid may be heated in the second heat exchanger 108 via a transfer
of heat from the gaseous effluent of the separator 106. In this
heating stage, the gaseous effluent in the second heat exchanger
108 is at a temperature above the utility fluid, so that the second
heat exchanger 108 may heat the utility fluid and the utility fluid
may cool the gaseous effluent. Then, in block 136, the utility
fluid may be heated in the first heat exchanger 104. In this
heating stage, the effluent in the first heat exchanger 104 is at a
temperature above the utility fluid from the second heat exchanger
108. With this temperature differential, the effluent in the first
heat exchanger 104 may heat the utility fluid, while the utility
fluid may cool the effluent. Then, following the heating in the
first heat exchanger 104, the utility fluid may be further heated
in the hydrocarbon pyrolysis unit 102, as shown in block 138. In
particular, if the utility fluid is feed water, it may be heated in
the hydrocarbon pyrolysis unit 102 to convert it into superheated,
super-high pressure (SHP) steam. Then, at block 140, the heated
utility fluid may be utilized in other processes. As an example,
the heated utility fluid may be used to drive the large turbines in
the other sections of the plant, such as the recovery section of
the steam cracker, for example.
[0037] Beneficially, the use of two stages of heat exchangers in
the configuration provides a mechanism to recover heat from the
hydrocarbon cracking process and to heat the utility fluid more
efficiently than possible with a single heat exchanger. That is,
this configuration of two heating stages in this sequence provides
a more efficient countercurrent flow arrangement for the different
temperature streams.
[0038] As may be appreciated, the temperatures of the various units
may vary depending on the quality of the hydrocarbon feed or other
operation considerations. For typical operation, the furnace outlet
temperature of the hydrocarbon cracked effluent may include
temperatures from about 760.degree. C. to about 930.degree. C.
(1400.degree. F. to 1706.degree. F.). The first heat exchanger
process inlet temperature may range from about 760.degree. C. to
about 930.degree. C. (1400.degree. F. to 1706.degree. F.), or
preferably about 816.degree. C. (1500.degree. F.), while the first
heat exchanger process outlet temperatures may range between about
343.degree. C. and about 650.degree. C. (about 650.degree. F. to
about 1200.degree. F.), preferably 343.degree. C. to 538.degree. C.
(650.degree. F. to 1000.degree. F.). The separator may operate at
temperatures from 190.degree. C. to about 350.degree. C. (about
374.degree. F. to about 662.degree. F.), or preferably from about
190.degree. C. to about 315.degree. C. (about 374.degree. F. to
about 599.degree. F.). The second heat exchanger inlet temperatures
may be from about 190.degree. C. to about 350.degree. C. (about
374.degree. F. to about 662.degree. F.), while the second heat
exchanger outlet temperatures may be between about 170.degree. C.
and about 300.degree. C. (about 338.degree. F. to about 572.degree.
F.).
[0039] For the heat recovery process, the utility fluid may be
provided at a pressure from about 2,172 kPa to about 17,340 kPa
(300 psig to 2500 psig), from about 10,450 kpa to about 13,982 kPa
(1,500 psig to about 2,000 psig), or about 10,450 kPa (1500 psig),
and having a temperature ranging from about 50.degree. C. to about
200.degree. C. (122.degree. F. to 392.degree. F.), preferably from
about 100.degree. C. to about 150.degree. C. (212.degree. F. to
302.degree. F.). As may be appreciated, the heat recovered in the
second heat exchanger may heat the utility fluid to a temperature
ranging from 100.degree. C. to about 300.degree. C. (about
212.degree. F. to about 572.degree. F.). Further, the heat recovery
in the first heat exchanger may heat the utility fluid in
temperature range from 205.degree. C. to about 355.degree. C.
(about 401.degree. F. to about 671.degree. F.). In the hydrocarbon
pyrolysis unit 102, the utility fluid may be further heated and
involve pressures ranging from about 2,172 kPa to about 17,340 kPa
(300 psig to 2500 psig), from about 10,450 kPa to about 13,982 kPa
(about 1,500 psig to about 2,000 psig), or about 10,450 kPa (about
1500 psig), and involve a temperature range from about 490.degree.
C. to about 550.degree. C. (about 914.degree. F. to about
1022.degree. F.).
[0040] Further, as may be appreciated, another optional heating
stage may be utilized in the process. For example, the utility
fluid may be heated by the hydrocarbon pyrolysis unit 102 between
the second heat exchanger 108 and the first heat exchanger 104.
That is, the utility fluid heated in the second heat exchanger 108
may be passed through the hydrocarbon pyrolysis unit 102 prior to
being provided to the first heat exchanger 104. In this manner,
additional heat may be recovered in the process.
[0041] As an alternative embodiment, FIG. 2 is a block flow diagram
200 of a process for recovering heat from the cooling of
hydrocarbon cracked effluent according to an alternative exemplary
embodiment of the present techniques. The flow diagram 200 includes
some similar equipment and operations similar to the blocks
previously discussed in reference to the flow diagram 100 of FIG.
1. Accordingly, for simplicity, the flow diagram 200 refers certain
blocks previously described in the disclosure above with reference
to FIG. 1. However, in the flow diagram 200, an additional heating
stage is utilized along with additional units to recover additional
heat from the hydrocarbon cracking process. In particular, the flow
diagram 200 includes one or more units 202 coupled to a third heat
exchanger 204, which is coupled between the second heat exchanger
108 and the fractionator 110. The one or more units 202 and third
heat exchanger 204 are arranged to provide an additional or third
heating stage for the utility fluid and to further cool the
effluent from the second heat exchanger 108 before the effluent is
provided to the fractionator 110.
[0042] To begin, the blocks 120-128 operate similar to the
discussion above. However, the effluent from block 128 may be
passed to the one or more units 202 in block 212. The one or more
units 202 may be used to recover additional heat from the effluent
from the second heat exchanger 108 and may also be used to increase
the temperature differential between the second heat exchanger 108
and the third heat exchanger 204 to further enhance the heat
recover in the system. In particular, the one or more blocks 212
may include one or more steam generators, such as a medium pressure
generator, a low pressure generator or a combination thereof to
recover additional heat and increase the temperature differential
between the second heat exchanger 108 and the third heat exchanger
204.
[0043] Regardless, heat may be recovered from the effluent passing
through the one or more units 202, as shown in block 214. Similar
to the discussion above regarding the first heat exchanger 104 and
second heat exchanger 108, the heat of the effluent may be
transferred to the utility fluid through a third heat exchanger
204, which may be a shell and tube heat exchanger, for example. In
this stage, the effluent may be cooled from a temperature at the
inlet of the third heat exchanger 204 to a third heat exchanger
outlet temperature. This temperature range in the third heating
stage 204 may again vary depending on the different hydrocarbon
feeds and operational settings for the other units in the
configuration.
[0044] Then, at block 130, the effluent from the third heat
exchanger 204 may be provided to another unit for further
processing of the effluent, which may be similar to the discussion
above.
[0045] As part of the heat recovery in the proposed arrangement,
the utility fluid is heated in various stages as described above in
relation to blocks 134-138. However, in this flow diagram 200, an
additional or third heating stage is performed. To begin, the
utility fluid is provided in block 132. Then, the utility fluid is
heated in block 216. In particular, the utility fluid may be heated
in the third heat exchanger 204 from the effluent. In this heating
stage, the effluent in the third heat exchanger 204 is at a
temperature above the utility fluid, so that the third heat
exchanger 204 may heat the utility fluid and the utility fluid may
cool the effluent. Then, the utility fluid may be further heated in
other heat exchangers 104 and 108 along with the hydrocarbon
pyrolysis unit 102 and used by other processes, as described above
in blocks 134-140.
[0046] Similar to the discussion above for FIG. 1, the temperatures
of the various units may vary depending on the quality of the
hydrocarbon feed or other operation considerations. For typical
operation, the furnace outlet temperature, the first heat exchanger
inlet and outlet temperatures, separator inlet and outlet
temperatures and second heat exchanger inlet and outlet
temperatures may be similar to the example above. However, the
third heat exchanger inlet temperature may be from about
265.degree. C. to about 160.degree. C. (509.degree. F. to
320.degree. F.), while the third heat exchanger outlet temperatures
may be between about 210.degree. C. and about 125.degree. C. (about
410.degree. F. to about 257.degree. F.).
[0047] Further, for the heat recovery process, the utility fluid
may involve similar pressures and temperatures to those noted above
in the discussion of FIG. 1 for the first heat exchanger, second
heat exchanger and pyrolysis unit. The utility fluid for the third
heat exchanger may be operated at temperatures ranging from about
50.degree. C. at the inlet to about 250.degree. C. at the outlet
(122.degree. F. to 482.degree. F.), preferably from about
110.degree. C. at the inlet to about 175.degree. C. at the outlet
(230.degree. F. to 347.degree. F.), or more preferably at about
136.degree. C. at the inlet to about 157.degree. C. at the
outlet.
[0048] As may be appreciated various additional embodiments may be
utilized to further enhance the heat recovery for the hydrocarbon
cracking system. As an example, the one or more units 202 may
include a medium pressure steam generator coupled between the
second heat exchanger 108 and the third heat exchanger 204. This
generator may be used to raise general purpose steam for heating,
reboiling, or the like and/or it may be used to generate dilution
steam for the hydrocarbon cracking process or another process. That
is, the dilution steam may be combined with the hydrocarbon feed
prior to or within the hydrocarbon pyrolysis unit 102, which may be
a steam cracking reactor, to improve yields, mitigate coking, and
preserve the metallurgy of the tubes within the furnace or related
equipment. The medium pressure generator may operate steam at a
pressure of about 150 psig (1,034 kpa) at the furnace inlet.
Accordingly, the medium pressure generator conveniently generates
steam at about this pressure, making it a good fit for dilution
steam production. As another example, the one or more units may
include a low pressure generator coupled between the second heat
exchanger 108 and the third heat exchanger 204. This generator may
be used to raise general purpose steam for heating, reboiling, or
the other suitable processes. In yet another example, a medium
pressure generator and a low pressure generator may be coupled
between the second heat exchanger and the third heat exchanger.
[0049] In addition to the above embodiments, various units may be
bypassed to provide additional functionality. For example, in the
flow diagram 200, the flow of the utility fluid may include
bypassing one of the upstream heat exchangers (such as the second
heat exchanger 108 or third heat exchanger 204) prior to being
provided to the first heat exchanger 104. That is, the second heat
exchanger 108 may receive utility fluid from a source, such as a
boiler or deaerator, and provide it to the first heat exchanger 104
(bypassing the third heat exchanger 204). Alternatively, the third
heat exchanger 204 may receive utility fluid from a source, such as
a boiler or deaerator, and provide it to the first heat exchanger
104 (bypassing the second heat exchanger 108). This process flow
may be utilized to manage the heating of the utility fluid.
[0050] As yet another example, the heated utility fluid from an
upstream heat exchanger in the utility fluid stream (such as the
second heat exchanger 108 or third heat exchanger 204) may be
passed through the hydrocarbon pyrolysis unit 102 (e.g., the
convection section of the furnace) prior to being provided to the
first heat exchanger 104. This may provide an additional heating
stage for the utility fluid. That is, the utility fluid may be
pre-heated before the first heat exchanger 104 transforms the
utility fluid into a super-high pressure fluid, such as steam, for
example. This configuration may efficiently utilize excess heat
available in the convection section.
[0051] As yet still another example, the heated utility fluid from
an upstream heat exchanger in the utility fluid stream (such as the
second heat exchanger 108 or third heat exchanger 204) may be
passed through the hydrocarbon pyrolysis unit 102 (e.g., the
convection section of the furnace) without being passed to the
first heat exchanger 104. This arrangement may bypass the first
heat exchanger 108, but still provide two or more heating stages
for the utility fluid. That is, the utility fluid may be pre-heated
in the second heat exchanger 108 and/or third heat exchanger 204
before the passing it through the hydrocarbon pyrolysis unit 102 to
generate the utility fluid into a super-high pressure fluid, such
as steam.
[0052] Regardless of the specific embodiment of the system (e.g.,
arrangement or configuration of the units in the hydrocarbon
cracking system), control mechanisms should be utilized to manage
the heat removal. That is, the hydrocarbon cracking system should
include heat control mechanisms to control the total amount of heat
removed from the effluent and the heat provided to the utility
fluid for various reasons. A first reason for this type of heat
control mechanism is that the amount of heat removed from the
effluent in the various heat exchangers and any other units may
need to be managed as the operation of the system becomes fouled or
changes over time. As a specific temperature range is desired at
the certain units in the process, such as at a mini-fractionator,
the heat removed from the effluent has to be managed. Otherwise,
the configuration of units may not produce the desired quantity of
reflux in the mini-fractionator.
[0053] One of the heat control mechanisms may include bypass valves
and bypass lines that control the flow rate of utility fluid to
certain heat exchangers and the temperature of the utility fluid at
the different units. With this mechanism, one or more bypass valves
and bypass lines may be implemented in an arrangement for bypassing
or controlling the flow of utility fluid to one or more of the heat
exchangers in one or more of the embodiments discussed above. That
is, one or more of the heat exchangers may be bypassed to manage
the heating of the utility fluid so that the temperature of the
utility fluid entering the furnace may be controlled to optimize
the furnace heat balance or may also be used to manage the cooling
of the effluent from the furnace at the various heat
exchangers.
[0054] Another heat control mechanism may include the use of one or
more back pressure controllers on fluids provided to the one or
more generators, such as the low pressure generator and/or medium
pressure generator. As an example, if a low pressure steam
generator is used in the system between the second heat exchanger
and third heat exchanger, then increasing the pressure in this
generator raises the boiling point on the water/steam side, which
raises the outlet temperature on the process side. The amount of
heat that can be removed in the second heat exchanger is limited by
temperature approach between the process stream and the water or
utility stream. The net result is that raising the pressure in the
low pressure steam generator increases the temperature and heat
content of the process effluent leaving the second heat exchanger.
As another example, a back pressure controller may be used with a
medium pressure generator. This back pressure controller may
operate similar to the operation described with regard to the low
pressure generator. The control on the medium pressure generator
may also be used as a supplement control to the back pressure
controller on the low pressure generator, if the medium pressure
generator is used with a low pressure generator arranged in a
sequence. Because medium pressure steam is generally more valuable
than low pressure steam, it may be preferable to raise back
pressure on low pressure generation as a first means of controlling
heat removal, and then to raise back pressure on medium pressure
steam generation if further reduction in heat removal is
required.
[0055] The heat recovered in heat exchangers may be sizeable.
Accordingly, certain configurations may include multiple heat
exchangers arranged in parallel. Each of these heat exchangers may
be coupled other units, such as low pressure generators and/or
medium pressure generators. For example, each of the heat exchanger
banks may include a heat exchanger, medium pressure generator, low
pressure generator and another heat exchanger coupled in series
with each other. Further, in this configuration, the parallel heat
exchanger banks may include isolation valves to allow each of the
heat exchanger banks to be removed from service (e.g., taken
offline) for cleaning or maintenance. Similarly, another heat
control mechanism may be to use the isolation valves to block flow
of the effluent into one or more of the heat exchanger banks if the
heat removal requirement is low. In this manner, the different
banks may be added or removed to further manage the heat
recovery.
[0056] Further, as it may be appreciated, the different heat
control mechanisms may be used together in certain embodiments to
provide additional flexibility in the control of the heat transfers
in the system. For example, the bypass valves and bypass lines may
be used with a back pressure controller for a low pressure
generator and a back pressure controller for a medium pressure
generator. Similar, to the discussion above, the back pressure
controller on the low pressure generator may be used first, then
the back pressure controller on the medium pressure generator may
be used next, and finally the bypass valves and bypass lines may be
used.
[0057] In this manner, the efficiency of the system is managed
based on the value of the heated utility fluid. That is, the heat
control mechanisms may be utilized to generate more SHP steam,
which is typically more valuable than medium pressure steam, which
is more valuable than low pressure steam. As an example, effluent
heat may be used to generate SHP steam, which may be utilized to
drive the large turbines in the other sections of the plant, such
as the recovery section of the steam cracker, for example. Further,
despite the fact that lower pressure steam has less utility than
the SHP steam because it does not deliver as much useful work,
steam raised at lower pressures may also be useful for certain
operations within the system. For example, lower pressure steam may
be used as furnace dilution steam or in reboiling towers. As such,
a heat recovery process may increase the efficiency of the
operation of the system if it recovers heat at several levels and
uses it in an effective manner.
[0058] As a specific example of the arrangement of units in the
hydrocarbon cracking system, FIG. 3 provides a schematic flow
diagram for recovering heat from hydrocarbon cracked effluent
according to another alternative exemplary embodiment of the
present techniques. In this schematic flow diagram 300, the
hydrocarbon cracking system may include various units, such as a
furnace 302, a first heat exchanger (e.g., a primary transfer line
exchanger) 304, a vapor/liquid separator 306, a second heat
exchanger (e.g., a first shell and tube heat exchanger) 308, a
medium pressure generator 310, a low pressure generator 312, a
third heat exchanger (e.g., a second shell and tube heat exchanger)
314, and a mini-fractionator 316. Each of these units may be
arranged and in fluid communication with each other through the
specific configuration and coupled together through various
connections (e.g., tubes, couplings, valves, etc.), as may be
appreciated by those skilled in the art. Further, the utility fluid
and the effluent from the furnace may be separate streams that do
not commingle from the furnace outlet through the third heat
exchanger outlet.
[0059] The process begins with the hydrocarbon feed being provided
to a furnace 302 via a line 303. The hydrocarbon feed may also be
combined with a dilution fluid, such as steam, which is provided by
a line 305. The hydrocarbon feed may be cracked in the furnace 302
to generate an effluent that is provided to the first heat
exchanger 304, and then the effluent is passed to the vapor-liquid
separator 306. The vapor-liquid separator 306 separates gaseous
effluent and liquid effluent into two different streams. In
particular, the vapor-liquid separator 306 may be utilized to
separate liquid effluent (e.g., bottom products, such as steam
cracked tar) from the gaseous effluent after it is initially cooled
in the first heat exchanger 304. In some embodiments, after leaving
the first heat exchanger 304, the cooled effluent stream may be
quenched with a liquid quench oil or liquid water, introduced via a
quench line 319 between the outlet of the first heat exchanger 304
and the inlet of the vapor-liquid separator 306 to provide
supplemental cooling. The liquid effluent from the vapor-liquid
separator 306 may be removed via line 322 and may be further in
other units (not shown).
[0060] The gaseous effluent is provided from the vapor-liquid
separator 306 to a bank of units coupled in series, which include
the second heat exchanger 308, the medium pressure generator 310,
the low pressure generator 312, and the third heat exchanger 314.
This bank of units may be used to cool the effluent prior to it
passing to the mini-fractionator 316. In this bank of units, the
medium pressure generator 310, followed by a low pressure generator
312 may be used to generate steam for other units, such as the
mini-fractionator 316 or other equipment in this system or other
systems. The proposed configuration may be particularly
advantageous with the mini-fractionator 316 because it can utilize
the higher temperatures available in the generators 310 and 312 for
additional utility fluid preheating. The mini-fractionator 316 may
be coupled to other downstream units to further processing the
effluent stream and to separate out the desired olefins.
[0061] As noted above, the use of the different heat exchangers
304, 308, and 314, along with the furnace 302, provides various
heating stages for the utility fluid provided via line 320. The
utility fluid may be provided from a boiler or deaerator (not
shown) and may include boiler feed water as the utility fluid
within the system. In this configuration, the utility fluid may be
heated initially at the third heat exchanger 314, then at the
second heat exchanger 308 and then at the first heat exchanger 304
or preheated at the furnace 302 before the utility fluid is finally
heated in the furnace 302 and provided at outlet 324 for other
equipment, such as turbines, other units, or as an input stream
into different processes.
[0062] To control the heat transfer within the system, the heat
control mechanisms may include the bypass valve 323 coupled between
the input line 320 for the utility fluid, the third heat exchanger
314 and the outlet of the second heat exchanger 308 via bypass
lines, tubes or the like. The bypass valve 323 may be configured to
restrict the flow of utility fluid to the units or may be
configured to provide flow to one of the third heat exchanger 314
and the outlet of the second heat exchanger 308. As an example, in
a first position, the bypass valve 323 may be configured to
restrict at least a portion of the utility fluid from passing to
the third heat exchanger 314 from the boiler or deaerator and
direct at least a portion of the utility fluid to the first heat
exchanger 304 via a bypass line. Similarly, in a second position,
the bypass valve 323 may direct at least a portion of the utility
fluid to pass to the third heat exchanger 314 from the source and
restrict at least a portion of the utility fluid from passing
through the bypass line to the first heat exchanger 304. As may be
appreciated, the restriction of flow may block flow or only a
portion of the flow, depending on the valves and lines
utilized.
[0063] In addition, other heat control mechanisms include the
medium pressure valve 326 and the low pressure valve 328. As
discussed above, these valves 326 and 328 may be used to control
the temperature of the gaseous effluent passing through medium
pressure generator 310 and the low pressure generator 312,
respectively. The medium pressure valve 326 is coupled to the
medium pressure generator 310 between an inlet 330 of boiler feed
fluid and outlet of medium pressure steam 332. The low pressure
valve 328 is coupled to the low pressure generator 312 between an
inlet 334 of boiler feed fluid and outlet of low pressure steam
336. In particular, the medium pressure valve 326 may be used to
increase the pressure within the medium pressure generator 310 to
raise the boiling point of the boiler feed water, which raises the
outlet temperature for the medium pressure generator 310.
Similarly, the low pressure valve 328 may be used to increase the
pressure within the low pressure generator 312 to raise the boiling
point of the boiler feed water, which raises the outlet temperature
for the low pressure generator 312.
[0064] The specific temperatures utilized in the operation of the
system may vary depending on the specific configuration. For
example, the outlet of the furnace 302 may be operated to be about
760.degree. C. (about 1400.degree. F.), which may be the same
temperature at the inlet of the first heat exchanger 304. The first
heat exchanger 304 along with direct quench oil or water may cool
the effluent to a temperature of about 300.degree. C. (about
572.degree. F.), which is the temperature utilized for the
separation. The gaseous effluent from the separator 306 may be
provided to the second heat exchanger at a temperature of about
299.degree. C. (about 570.degree. F.), which is cooled to a
temperature of about 260.degree. C. (about 500.degree. F.). The
effluent may then pass through the generators 310 and 312 and be
provided to a third heat exchanger 314 at a temperature of about
166.degree. C. (about 330.degree. F.). The third heat exchanger 314
may cool the effluent to a temperature of about 154.degree. C.
(about 310.degree. F.).
[0065] The utility fluid may utilize the various stages to heat the
utility fluid, as discussed above. In particular, for this example,
the utility fluid may be provided to the third heat exchanger at a
temperature about 125.degree. C. (about 257.degree. F.). The third
heat exchanger may use the effluent to heat the utility fluid to a
temperature of about 149.degree. C. (about 300.degree. F.). Then,
the utility fluid may be provided to the second heat exchanger 308,
which may further heat the utility fluid to a temperature of about
268.degree. C. (about 515.degree. F.). The utility fluid may then
be heated in the first heat exchanger 304 to a temperature of about
316.degree. C. (about 600.degree. F.). Then, the utility fluid may
be further heated to a temperature of about 538.degree. C. (about
1000.degree. F.) in the convection section of furnace 302.
[0066] FIG. 4 is another schematic flow diagram for recovering heat
from the cooling of cracked hydrocarbon effluent according to
another alternative exemplary embodiment of the present techniques.
In this figure, the hydrocarbon feed is passed through two
separators 402 and 404 that are coupled to the hydrocarbon
pyrolysis unit 302. These separators 402 and 404 are used as high
temperature knock-out drums, which remove resid and asphaltene
molecules from a hydrocarbon feed before entering the radiant
section of the hydrocarbon pyrolysis unit 302. Beneficially, the
use of the separators 402 and 404 may utilize the heated utility
fluid in this specific configuration to further enhance the
efficiency of the system and further optimize olefin recovery.
[0067] Typically, steam cracking furnaces, which employ a
separator, such as an out-board knock-out drum integrated between
the convection and radiant sections, operate only up to about
454.degree. C. (about 850.degree. F.). These typical configurations
are noted in other patents, such as U.S. Pat. Nos. 7,097,758;
7,138,047; 7,193,123; 7,235,705 and 7,247,765. Operating above
454.4.degree. C. (about 850.degree. F.) may result in excess
fouling downstream of the separator. This fouling may be a result
of a two-reaction mechanism. First, the vapor in the separator
above the tangential inlet cracks via endothermic reactions and the
separator loses some heat. These effects combine to reduce the
vapor temperature by about -7.degree. C. to about -1.degree. C.
Because the vapor is at its dew point when it enters the separator,
any cooling condenses the heaviest molecules. Vapor/liquid
equilibrium calculations predict that the resulting heavy liquid
(entrained in the vapor) is rich in 760.degree. C.+ (1400.degree.
F.+) molecules, which are the coke precursors. Second, the heavy
liquid undergoes condensation reactions that produce ever larger
multi-ring aromatics, which eventually result in the multi-ring
aromatics becoming coke.
[0068] As a result of this two-reaction mechanism, fouling
typically occurs in two locations, which are the piping downstream
of the separator and in the radiant inlet manifolds (RIMs). The
fouling in the RIM may result from some of the fouling precursors
remaining in the vapor phase or vaporizing in the lower convection
section. In the convection section, cracking and some condensation
reactions occur, but because the process temperature is rising, no
liquid is formed. These reactions may subsequently undergo rapid
condensation reactions (condensation reactions likely follow 2nd
order kinetics). However, in the crossover piping and RIM heat
losses and continued endothermic cracking reactions cool the
process by about 10.degree. C. to about 38.degree. C. (about
50.degree. F. to about 100.degree. F.). Here also the condensation
reactions are very rapid even in the vapor phase. Once the
temperature drops below the dew point of these newly condensed
multi-ring aromatics, they become liquid and coke rapidly, which
deposit in the relatively low velocity in the RIM.
[0069] Accordingly, reducing the residence time in the separator
may reduce fouling to a manageable level. This aspect may reduce
fouling in the piping downstream of the separator. However, this
may not reduce fouling in the crossover piping and/or inlet
manifold because the 760.degree. C.+ (1400.degree. F.+) vapor
molecules entering the separator are still present in the lower
convection section, crossover piping and RIM where cracking and
condensation may still occur. In fact, reducing the residence time
in the drum could increase the fouling in the RIM.
[0070] Naphtha, kerosene and hydrocrackate cracking in the
hydrocarbon pyrolysis unit, which may be a steam cracking furnace,
with the separator indicates that 760.degree. C.+ (1400.degree.
F.+) molecules may cause the fouling, not just the cracking and
condensation reactions. The hydrocarbon feed typically enter
separators at 490.degree. C. to 502.degree. C. (915.degree. F. to
935.degree. F.), about 21.degree. C. to 32.degree. C. (about
70.degree. F. to 90.degree. F.) higher than atmospheric resids. The
feed experiences the same separator residence time and marginally
higher temperatures in the lower convection section, crossover
piping and RIM than the atmospheric resides, which has negligible
fouling. Accordingly, as no large (760.degree. C.+ (1400.degree.
F.+)) molecules are present, the condensation reactions do not
produce molecules large enough to become a liquid as the process
temperature drops in the crossover piping and RIM. Thus, removal of
the 760.degree. C.+ (1400.degree. F.+) molecules in the vapor may
be beneficial, not just reducing separator residence time.
[0071] In this embodiment, the SHP generated by passing the utility
fluid through the hydrocarbon pyrolysis unit (e.g., furnace 302)
may be used along with the separators 402 and 404 to reduce fouling
in the system. In this configuration, the cut from the separator
402 may be deep to vaporize significant coke producing molecules
(e.g., 760.degree. C.+ (1400.degree. F.+)). A small amount of clean
steam cracking feed may also be added to the overhead vapor in a
venturi mixer 406. This clean steam cracking feed condenses the
coke producing molecules. The liquid produced in the venturi mixer
406 is removed by the separator 404. The vapor is conveyed from the
separator 404 to the lower convection section, then to the radiant
section. With the vapor 760.degree. C.+ (1400.degree. F.+) removed,
fouling is negligible allowing the separators 402 and 404 to
operate at high temperature of 482.degree. C. to 510.degree. C.
(900.degree. F. to 950.degree. F.).
[0072] Clearly, the benefit of reducing fouling is the ability to
operate the separators at higher temperatures. The higher
operational temperatures increase the fraction of the resid or
crude that vaporizes, and subsequently cracks into valuable
produces. But the separator bottoms become more viscous requiring
more low viscosity fluxant per unit mass to meet fuel oil viscosity
specifications. However, the gross fluxed bottoms still
significantly decreases as nominal cut point temperature increase.
For example, increasing the nominal cut point temperature of Arab
heavy crude from 538.degree. C. to 593.degree. C. (1000.degree. F.
to 1100.degree. F.) (about the same as increasing the drum
temperature from 449.degree. C. to 504.degree. C. (840.degree. F.
to 940.degree. F.)) reduces the fluxed bottoms from 47 pounds (lbs)
(21 kilograms (kg))/100 lbs (46 kg) of crude to 40 lbs (18 kg)/100
lbs (46 kg) of crude. That is, an additional 7 lbs (3 kg)/100 lbs
(46 kg) of crude are cracked to valuable products.
[0073] To operate, hydrocarbon feed, such as crude or resid, is
preheated in the upper convection section, and then the hydrocarbon
feed is mixed with superheated dilution steam. The superheated
dilution steam may be provided from outlet 324, which is discussed
above. The mixture is further heated in the convection section,
which may include heating to about 510.degree. C. (about
950.degree. F.), as an example. Because the piping is continuously
washed by the large fraction of liquid remaining, no coke is
formed. The two-phase process stream is conveyed to the separators
402 and 404 by piping, which includes various bends and joints. The
bends tend to convert mist flow to stratified or annular flow. The
separators 402 and 404 may dramatically reduce the size of the
piping to the separator 402 and the size of both separators 402 and
404. That is, because the separators 402 and 404 are coupled in
fluid communication in series, each separator does not have to be
as efficient at separating the vapor from the liquid as a single
separator. For example, if a single separator only entrains 1% of
the liquid, two separators in series can each entrain 10% of the
liquid resulting in the same aggregate 1% liquid entrainment. As a
result, the dual separator tangential inlets inner diameter (ID)
may be about 50% smaller than for single separator and the
separators ID may be about one-third smaller than the single
separator. Thus, even though there are two separators, the total
separator metal required is about 50% less than the single
separator.
[0074] The vapor and some liquid exiting the separator 402 is
conveyed to a venturi mixer 406 where the vapor is partially quench
by diesel oil, hydrocrackate, wax, condensate or even quench oil.
The quench turbulently mixes and vaporizes, while condensing the
heaviest molecules in the vapor phase. The venturi mixer 406 does
not have any stagnant points where the liquid may coke. This is an
advantage over trays or packing where stagnant liquid can become
coke. The amount of quench is small to reduce the 760.degree. C.+
(1400.degree. F.+) molecules in the vapor by nearly an order of
magnitude. This aspect is indicated from Table 1, which is
below.
TABLE-US-00001 TABLE 1 The effect of quench on 1400.degree. F. in
drum vapor Drum vapor, klbs/hr 110 110 110 110 slip stream to
partial condenser, 10 10 10 10 Klbs/hr hydrocarbon condensed,
Klbs/hr 0 1 1.5 2 duty, MBtu/hr 0 0.42 0.55 0.68 ppm (wt)
1400.degree. F. in overhead vapor 10 5 2.5 1.3
[0075] The far right column of this table indicates that removing
0.68 million British thermal units per hour (MBtu/hr) (199 kilowatt
(kW) reduces 760.degree. C.+ (1400.degree. F.+) molecules in the
vapor by a factor of six. Energy balance calculations predict that
roughly 1,300 (lb/hr) (591 kg/hr) of quench removes the 0.68
MBtu/hr (199 kW). The piping downstream of the venturi mixer 406
has bends to convert the mist flow back into stratified or annular
flow before entering the separator 404. The process stream enters
the separator 404 via one or two tangential inlets. Because
splitting the flow may cause flow imbalances and stagnant spots,
one tangential inlet may be preferred. A single entry separator 404
and the piping to it may be marginally larger than the two entry
separator 402.
[0076] The separator 404 removes roughly 90% of the remaining
liquid attaining the 99% aggregate vapor/liquid separation
efficiency. In a preferred embodiment, once stratified or annular
flow is established in the piping to each of the separators 402 and
404, the process mixture can initially enter reducers that increase
the IDs by 10% to 20%, and then enter piping with these larger IDs.
This reduction of the process velocity by 17% to 31% upstream of
the separators 402 and 404 may increase the vapor/liquid separation
efficiency from 99% to 99.5% to 99.7%. Similar to the separator
402, the separator 404 may have a boot where the bottoms are
quenched to roughly 343.degree. C. (650.degree. F.), to hinder
cracking and coking reactions. Optionally, the liquid then passes
through a dual-return bend trap before mixing with the process
stream upstream of the separator 402. This dual return bend
provides the head necessary to effect flow into the piping upstream
of the separator 402. The overhead vapor from the separator 404,
which has significantly less 760.degree. C.+ (1400.degree. F.+)
molecules, is further preheated in the low convection section and
passes through the crossover piping and RIM with minimal fouling.
The hydrocarbon feed then cracks in the radiant section and is
further processed, as discussed above.
[0077] Further embodiments may also be utilized to further enhance
the operation of this configuration. For example, steam stripping
may be provided at inlet 410. The steam stripping of bottoms of the
separator 402 may be utilized to vaporize light material trapped in
the heavy resid bottoms producing additional hydrocarbon feed.
Further, superheated steam, which may be provided from outlet 324,
may be added at inlet 408 into the vapor space above the inlet to
the separator 404. This embodiment may prevent any condensation
from occurring upstream of the lower convection section. Moreover,
in another embodiment, the radiant section may be configured to be
marginally taller allowing a lower crossover temperature (XOT)
without excessive radiant heat flux and coking. A lower XOT may
significantly increase the gasoil cracking selectivity and ethylene
yield.
[0078] In another embodiment, the present techniques relate to:
1. A method for cracking a hydrocarbon feed, the method comprising:
[0079] providing a hydrocarbon feed to a hydrocarbon pyrolysis unit
to create a cracked effluent; [0080] passing at least a portion of
the cracked effluent from the hydrocarbon pyrolysis unit through a
first heat exchanger; [0081] separating the at least a portion of
the cracked effluent from the first heat exchanger into a gaseous
effluent and a liquid effluent; [0082] passing at least a portion
of the gaseous effluent through a second heat exchanger; [0083]
passing the at least a portion of the effluent from the second heat
exchanger to a fractionator; [0084] recovering heat from the at
least a portion of the effluent in the second heat exchanger by
passing a utility fluid through the second heat exchanger; and
[0085] recovering heat from the at least a portion of the cracked
effluent in the first heat exchanger by passing the utility fluid
from the second heat exchanger through the first heat exchanger. 2.
The method of paragraph 1, comprising passing the utility fluid
from the first heat exchanger through the hydrocarbon pyrolysis
unit to heat the utility fluid. 3. The method of paragraphs 1 and
2, comprising passing the at least a portion of the effluent from
the second heat exchanger to one or more steam generators before
passing the at least a portion of the effluent from the second heat
exchanger to the fractionator. 4. The method of paragraph 3,
comprising passing the at least a portion of the effluent from the
one or more steam generators through a third heat exchanger before
passing the at least a portion of the effluent to the fractionator.
5. The method of paragraph 4, comprising recovering heat from the
at least a portion of the effluent from the one or more steam
generators in the third heat exchanger by passing the utility fluid
through the third heat exchanger before passing the at least a
portion of the effluent from the one or more generators to the
fractionator. 6. The method of any of the preceding paragraphs,
comprising adjusting valves on the one or more steam generators to
control the heat recovery from the at least a portion of the
effluent passing through the one or more steam generators. 7. The
method of any of the preceding paragraphs, wherein the utility
fluid is heated in a deaerator prior to passing through the first
heat exchanger. 8. The method of any of the preceding paragraphs,
comprising driving a turbine with the heated utility fluid from the
first heat exchanger. 9. The method of any of the preceding
paragraphs, wherein the at least a portion of the cracked effluent
from the first heat exchanger is cooled in a direct quench to at
least a temperature at which tar, formed by reaction among
constituents of the effluent, condenses, prior to the separating of
the gaseous effluent and the liquid effluent. 10. A hydrocarbon
cracking system comprising: [0086] a hydrocarbon pyrolysis unit
configured to: [0087] receive a hydrocarbon feed; and [0088] create
a cracked effluent from the hydrocarbon feed; [0089] a first heat
exchanger in fluid communication with the hydrocarbon pyrolysis
unit and configured to: [0090] cool at least a portion of the
cracked effluent from the hydrocarbon pyrolysis unit; and [0091]
heat at least a portion of a utility fluid; and [0092] a separator
in fluid communication with the first heat exchanger and configured
to separate the at least a portion of the cracked effluent into
liquid effluent and gaseous effluent; [0093] a second heat
exchanger in fluid communication with the separator and configured
to: [0094] cool at least a portion of the gaseous effluent from the
separator; [0095] heat the utility fluid prior to the first heat
exchanger receiving the at least a portion of the utility fluid;
and [0096] a fractionator in fluid communication with the second
heat exchanger and configured to receive the at least a portion of
the effluent from the second heat exchanger. 11. The system of
paragraph 10, wherein the hydrocarbon pyrolysis unit is configured
to: [0097] heat the at least a portion of the utility fluid from
the first heat exchanger, wherein the at least a portion of the
utility fluid and the at least a portion of the cracked effluent
are maintained in separate non-commingling streams in the
hydrocarbon pyrolysis unit. 12. The system of paragraph 10,
comprising one or more steam generators in fluid communication
between the second heat exchanger and the fractionator and
configured to pass the at least a portion of the effluent from the
second heat exchanger to the fractionator. 13. The system of
paragraph 12, comprising a third heat exchanger in fluid
communication between the one or more steam generators and the
fractionator and configured to cool the at least a portion of the
effluent before passing the at least a portion of the effluent to
the fractionator. 14. The system of paragraph 13, wherein the third
heat exchanger is in fluid communication with the second heat
exchanger and configured to recover heat from the at least a
portion of the effluent by passing the utility fluid through the
third heat exchanger prior to the second heat exchanger receiving
the utility fluid; and wherein the utility fluid and the at least a
portion of the effluent are maintained in separate non-commingling
streams in the second heat exchanger. 15. The system of paragraph
14, comprising a bypass valve coupled between a source of the
utility fluid, the first heat exchanger and the third heat
exchanger and configured to: [0098] in a first position, restrict a
first a portion of the utility fluid from passing to the third heat
exchanger from the source and direct a remaining first portion of
the utility fluid to the first heat exchanger via a bypass line;
and [0099] in a second position, direct a second portion of the
utility fluid to pass to the third heat exchanger from the source
and restrict a second remaining portion of the utility fluid from
passing through the bypass line to the first heat exchanger. 16.
The system of any one of the preceding paragraphs 12-15, comprising
a control valve coupled to at least one of the one or more steam
generators and configured to control the cooling of the at least a
portion of the effluent passing through the one or more steam
generators. 17. The system of any of the preceding paragraphs
10-16, comprising a deaerator in fluid communication with the
second heat exchanger and configured to preheat the utility fluid
prior to passing the utility fluid to the second heat exchanger.
18. The system of any of the preceding paragraphs 10-17, wherein
the first heat exchanger is configured to cool the at least a
portion of the cracked effluent from the hydrocarbon pyrolysis unit
and provide the at least a portion of the cracked effluent to a
direct quench that cools the at least a portion of the cracked
effluent to a temperature at which tar, formed by reaction among
constituents of the at least a portion of the cracked effluent,
condenses. 19. The system of any of the preceding paragraphs 10-18,
comprising a drive turbine configured to receive the at least a
portion of the heated utility fluid from the hydrocarbon pyrolysis
unit. 20. The system of any of the preceding paragraphs 10-19,
wherein the utility fluid and the at least a portion of the
effluent are maintained in separate non-commingling streams. 21. A
method for steam cracking a hydrocarbon feed, the method
comprising: [0100] providing a hydrocarbon feed to a hydrocarbon
pyrolysis unit to create a cracked effluent; [0101] separating at
least a portion of the cracked effluent from the hydrocarbon
pyrolysis unit, where gaseous effluent is separated from liquid
effluent including steam cracked tar; [0102] cooling at least a
portion of the gaseous effluent in a first heat exchanger; [0103]
passing the at least a portion of the effluent from the first heat
exchanger to one or more steam generators; [0104] cooling the at
least a portion of the effluent from the one or more steam
generators in a second heat exchanger; and [0105] passing the at
least a portion of the effluent from the second heat exchanger to a
fractionator. 22. The method of paragraph 21, comprising passing
the at least a portion of the cracked effluent from the hydrocarbon
pyrolysis unit through a third heat exchanger before passing the at
least a portion of the cracked effluent to a separator. 23. The
method of any of the preceding paragraphs 21 and 22, comprising
heating a utility fluid by passing the utility fluid through the
hydrocarbon pyrolysis unit and using the heated utility fluid in an
additional process. 24. The method of paragraph 23, recovering heat
from the at least a portion of the effluent in the first heat
exchanger by passing the utility fluid by through the first heat
exchanger prior to passing the utility fluid through hydrocarbon
pyrolysis unit. 25. The method of paragraph 24, comprising
recovering heat from the at least a portion of the effluent in the
second heat exchanger by passing the utility fluid through the
second heat exchanger prior to passing the utility fluid through
the first heat exchanger. 26. The method of paragraph 25,
comprising adjusting valves on the one or more steam generators to
control the heat recovery from the at least a portion of the
effluent passing through the one or more steam generators. 27. The
method of paragraph 24, wherein the utility fluid is heated in a
deaerator prior to passing through the first heat exchanger. 28.
The method of paragraph 22, wherein the at least a portion of the
cracked effluent is cooled in the third heat exchanger to at least
a temperature above the temperature at which tar, formed by
reaction among constituents of the gaseous effluent, condenses. 29.
The method of any of the preceding paragraphs 23-28, wherein using
the heated utility fluid in the additional process comprises
driving a turbine with the heated utility fluid. 30. A gaseous
effluent handling system comprising: [0106] a hydrocarbon pyrolysis
unit configured to: [0107] receive a hydrocarbon feed; and [0108]
create a cracked effluent from the hydrocarbon feed; and [0109] a
separator in fluid communication with the hydrocarbon pyrolysis
unit and configured to separate liquid effluent having steam
cracked tar and gaseous effluent from at least a portion of the
cracked effluent from the hydrocarbon pyrolysis unit; and [0110] a
first heat exchanger in fluid communication with the separator and
configured to cool at least a portion of the gaseous effluent from
the separator; [0111] one or more steam generators in fluid
communication with the first heat exchanger and configured to
receive the at least a portion of the effluent from the first heat
exchanger; [0112] a second heat exchanger in fluid communication
with the one or more generators and configured to cool the at least
a portion of the effluent from the one or more steam generators;
and [0113] a fractionator in fluid communication with the second
heat exchanger and configured to receive the at least a portion of
the effluent from the second heat exchanger. 31. The system of
paragraph 30, comprising a third heat exchanger in fluid
communication between the separator and the hydrocarbon pyrolysis
unit and configured to cool the at least a portion of the cracked
effluent passing through the third heat exchanger to the separator.
32. The system of paragraph 30, wherein the hydrocarbon pyrolysis
unit is configured to heat a utility fluid by passing the utility
fluid through the hydrocarbon pyrolysis unit. 33. The system of
paragraph 32, wherein the first heat exchanger is configured to
recover heat from the at least a portion of the effluent in the
first heat exchanger by passing the utility fluid by through the
first heat exchanger prior to passing the utility fluid through
hydrocarbon pyrolysis unit. 34. The system of paragraph 33, wherein
the second heat exchanger is configured to recover heat by passing
the utility fluid through the second heat exchanger prior to
passing the utility fluid through the first heat exchanger. 35. The
system of paragraph 34, comprising one or more valves coupled to
the one or more steam generators and configured to adjust the heat
recovery from the at least a portion of the effluent passing
through the one or more steam generators. 36. The system of any one
of paragraphs 30-34, comprising [0114] a first separator and a
second separator in fluid communication with a convection section
and a radiant section of the of hydrocarbon pyrolysis unit; [0115]
the first separator configured to receive hydrocarbon feed from the
convection section; and separate the hydrocarbon feed into a first
vapor feed and a first liquid feed; [0116] the second separator
configured to receive the first vapor feed; separate the first
vapor feed into a second vapor feed and a second liquid feed; pass
the second liquid feed to the first separator; and pass the second
vapor feed to the radiant section of the hydrocarbon pyrolysis unit
to create a cracked effluent.
[0117] The foregoing application is directed to particular
embodiments of the present techniques for the purpose of
illustrating it. It will be apparent, however, to one skilled in
the art, that many modifications and variations to the embodiments
described herein are possible. Further, some embodiments may be
preferably performed at least partly on a computer, i.e.,
computer-implemented embodiments of the present inventive method
are preferred, but not essential. All such modifications and
variations are intended to be within the scope of the present
invention, as defined in the appended claims.
* * * * *